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  Degradable ball sealers and methods for use in well treatmentRelated Patent Categories: Wells, Processes, Fluid Flow Causes Pellet To Block Opening In Wall Of ConduitDegradable ball sealers and methods for use in well treatment description/claimsThe Patent Description & Claims data below is from USPTO Patent Application 20070169935, Degradable ball sealers and methods for use in well treatment. Brief Patent Description - Full Patent Description - Patent Application Claims
PRIORITY [0001] This application claims benefit of priority to U.S. Provisional Patent Application Ser. No. 60/751,695, filed Dec. 19, 2005, the entire contents of which are incorporated by reference herein. FIELD OF THE INVENTION [0002] The invention relates to degradable ball sealer compositions, methods for their manufacture and methods for use in temporarily sealing casing perforations in wellbore stimulation treatments. In particular, oil degradable ball sealers comprised of copolymers of ethylene and one or more alpha-olefins and optionally finely graded filler material for adjusting the ball sealer specific gravity, methods for their manufacture by injection molding, and methods for their use in subterranean stimulation treatments is disclosed. DESCRIPTION OF RELATED ART [0003] It is common practice in completing oil and gas wells to set a string of pipe, known as casing, in the well and use a cement sheath around the outside of the casing to isolate the various formations penetrated by the well. To establish fluid communication between the hydrocarbon-bearing formations and the interior of the casing, the casing and cement sheath are perforated, typically using a perforating gun or similar apparatus. At various times during the life of the well, it may be desirable to increase the production rate of hydrocarbons using appropriate treating or stimulation fluids such as acids, water-treatment fluids, solvents or surfactants. If only a short, single pay zone in the well has been perforated, the treating fluid will flow into the pay zone where it is needed. As the length of the perforated pay zone or the number of perforated pay zones increases, the placement of the treating or stimulation fluid in the regions of the pay zones where it is needed becomes more difficult. For instance, the strata having the highest permeability will most likely consume the major portion of a given stimulation treatment, leaving the least permeable strata virtually untreated. [0004] Various techniques have been developed to redirect stimulation fluids towards lower permeability zones to ensure that damaged formations are sufficiently exposed to these fluids. One such technique for achieving diversion involves the use of downhole equipment such as packers. Although these devices can be effective, they are quite expensive because of the associated workover equipment required during the tubing-packer manipulations. Additionally, mechanical reliability tends to decrease as the depth of the well increases. As a result, considerable effort has been devoted to the development of alternative diverting methods for cased and perforated wells. [0005] One alternative is to redirect stimulation fluids toward lower permeability zones by using ball sealers to temporarily block perforations that exist across higher permeability zones. Generally, the ball sealers are pumped into the wellbore along with the formation treating fluid and are carried down the wellbore and onto the perforations by the flow of the fluid through the perforations into the formation. The balls seat upon the perforations receiving the majority of fluid flow and, once seated, are held there by the pressure differential across the perforations. The ball sealers are injected at the surface and transported by the treating fluid. Other than a ball injector and possibly a ball catcher, no special or additional treating equipment is required. Some of the advantages of utilizing ball sealers as a diverting agent include ease of use, positive shutoff, no involvement with the formation, and low risk of incurring damage to the well. Ball sealers are typically designed to be chemically inert in the environment to which they are exposed; to effectively seal, yet not extrude into the perforations; and to release from the perforations when the pressure differential into the formation is relieved. [0006] The oil and gas industry began using ball sealers as a diverting agent around 1956. Since that time the majority of wells have been completed at depths less than 15,000 ft, and as a result most commercially available ball sealers are designed to perform at temperatures and at pressures commonly associated with wells of depths less than 15,000 ft. In most cases these wells will have temperatures less than 250.degree. F. and maximum bottomhole pressures not exceeding 10,000 to 15,000 psi during a workover [Erbstoesser, S. R., Journal of Petroleum Technology, pp. 1903-1910 (1980)]. In recent years, however, technological developments have enabled the oil and gas industry to drill and complete wells at depths exceeding 15,000 ft., which will often have higher temperatures and pressures. For example, at a depth of around 25,000 ft., wellbore temperatures can exceed 400.degree. F., with bottomhole pressures approaching 20,000 psi during a workover. In addition to the high temperatures and pressures, wells completed at these depths often produce fluids like carbon dioxide (CO.sub.2) or hydrogen sulfide (H.sub.2S), and the stimulation fluid used may be a solvent like hydrochloric acid (HCl). Thus, conducting a workover using ball sealers in deep, hostile environment wells requires ball sealers capable of withstanding high pressures and temperatures while exposed to gases and solvents. The ball sealers must also resist changes in density to ensure satisfactory seating efficiency during a workover. [0007] Most commercially available ball sealers will have a solid, rigid core which resists extrusion into or through a perforation in the formation and an outer covering sufficiently compliant to seal, or significantly seal, the perforation. The ball sealers should not be able to penetrate the formation since penetration could result in permanent damage to the flow characteristics of the well. Commercially available ball sealers are typically spherical with a hard, solid core made from nylon, phenolic, syntactic foam, or aluminum. The solid cores may be covered with rubber to protect them from solvents and to enhance their sealing capabilities. Ball sealer diameters typically range from 5/8-in to 11/4 in, with specific gravities ranging from 0.8 to 1.9. With the exception of syntactic foam cores, most of the rubber-coated balls are designed to withstand hydrostatic pressures below 10,000 psi at temperatures below 200.degree. F. Specific gravities of rubber-coated balls typically range from 0.9 to 1.4. Ball sealers with syntactic foam cores are capable of withstanding hydrostatic pressures up to 15,000 psi at temperatures up to 250.degree. F., and have specific gravities ranging from 0.9 to 1.1. [0008] These ball sealers will, however, begin to degrade when temperatures or pressures exceed the design limits. Degradation can also occur when exposing ball sealers to fluids like HCl, CO.sub.2, or H.sub.2S. Additionally, in the case of rubber coated ball sealers, the perforation can actually cut the rubber coating in the area of the pressure seal. Once the ball sealer loses its structural integrity, the unattached rubber is free to lodge permanently in the perforation which can reduce the flow capacity of the perforation and may permanently damage the well. The cut rubber coating will also result in exposure of the ball core material to the stimulation fluid, possibly resulting in dissolution of the core material. The capability of a ball sealer to block a perforation will diminish notably if degradation results in excessive ball deformation or in a breakdown of ball material. A ball sealer must remain essentially not deformed and intact under high pressures and temperatures to effectively block a perforation during a workover. Thus, material strength and environmental resistance are important aspects of ball sealer design. [0009] Another important aspect of ball sealer design is density (or specific gravity). Past research and field studies indicate that the number of ball sealers that will seat onto perforations located inside a well (seating efficiency) depends on several factors, including the relative density of the ball sealer and the wellbore fluid. Erbstoesser [see Journal of Petroleum Technology (SPE Paper 8401), pp. 1903-1910 (1980)] observed that maximum seating efficiencies occurred when the ball density was 0.02 g/cc less than the workover fluid density which typically ranges from 0.8 g/cc to 1.3 g/cc. Thus, most workovers will require a low-density ball sealer in order to enhance seating efficiencies. Ball sealer density should also remain essentially constant to minimize changes between the relative density of the ball sealer and the wellbore fluid during a workover. There are various materials having high temperature and high pressure resistances. However, the problem with using these materials for a solid core ball sealer design is that these materials will typically have a high density as compared to common treating fluids. As a result, this higher density can prevent current commercial, solid core ball sealer designs made of high strength materials from seating against the perforations. [0010] A potential problem with commercial ball sealers is quality control during ball manufacturing. The densities of ball sealers delivered for use during a workover will often vary notably from specified values. The lack of proper quality control when forming the solid core material, coupled with irregularities when applying the rubber coating, can cause variations in the overall ball density, and such variations can notably affect seating efficiencies during a workover. Current ball sealer designs do not allow for adjustments to be made to the ball sealer density prior to initiation of a workover. Thus, because of inventory costs, only a select range of ball sealer densities are typically available for immediate use. Further problems associated with current ball sealer designs include problems associated with retrieving the balls from the wellbore in order to resume production, jamming of equipment downhole due to excess balls remaining in and surrounding the production pipe, and plugging of surface production valves when remaining ball sealers are picked up by the motion of the production fluid and carried to the surface. [0011] To summarize, deeper drilling has demanded stimulation jobs that are conducted under conditions that exceed the current temperature, pressure, and well-condition limitations of available low density ball sealers. Available low density ball sealers are typically not designed to withstand temperatures over 200.degree. F.-250.degree. F., hydrostatic pressures over 10,000-15,000 psi, or differential pressures over 1,500 psi. They are currently unable to perform effectively when exposed to hostile well environments because they deform excessively when exposed to the high temperatures and high bottomhole pressures often associated with deeper wells, particularly during long workovers or when exposed to solvents. Furthermore, those commercial ball sealers designed to withstand higher pressures or temperatures (e.g. ball sealers with rubber-covered, high strength, solid phenolic core) will have densities higher than the stimulation fluids used during the workover. Thus, the ball sealers will either not seat at all or seating efficiencies will decrease. The ability of commercial ball sealers to perform satisfactorily will decrease notably as temperatures begin to exceed 200.degree. F. (93.degree. C.). Ball sealer performance is limited further when hydrostatic pressures exceed 10,000 psi or when differential pressures across the perforations exceed 1,500 psi at high temperatures and pressures. These conditions are common during workovers in deep, hostile environment wells. For the foregoing reasons, a need exists for improved low density ball sealers which function properly in such hot, hostile environment wells, especially in the presence of acidic fluids. [0012] Ball sealer designs began in about 1955 with Derrick, et al (U.S. Pat. No. 2,754,910). Therein, a method for plugging perforations using spherical and polygonal shaped solid and hollow cores made from materials (light metal alloys, thermoplastics, thermosets) with a soft, thin coating applied to the surface was suggested. Derrick did not, however, discuss or suggest using high strength materials (which are typically very dense) for a rigid, thick-walled, hollow core ball or using his ball sealers in high temperature (>200.degree. F.), high pressure (>10,000 psi) applications. Further, Derrick's discussion was limited to subterranean applications at or below 10,000 psi. [0013] In 1978, Erbstoesser (U.S. Pat. No. 4,102,401) first introduced the concept of using solid core syntactic foam balls, or glass micro-spheres mixed with epoxy. This material is a hard, lightweight material capable of withstanding high pressures. In U.S. Pat. No. 4,421,167, Erbstoesser suggested using ball sealers as diverting agents in perforated casings, wherein the ball sealers comprised polymethylpentane and a nonelastomeric plastic protective covering. Erbstoesser later advanced the idea of using a more durable, rubber-like material called polyurethane as a coating for syntactic foam balls in U.S. Pat. No. 4,407,368. [0014] In U.S. Pat. No. 4,505,334, Doner, et al. suggested a method for making ball sealers by wrapping a thermostatic filament around a core, then curing the material. An elastomeric outer covering was described as being optional. In U.S. Pat. No. 4,702,316, Chung, et al., suggested a method for diverting steam in injection wells using ball sealers comprised of polymer compounds covered with a thin elastomer coating. The polymer compounds were described to include polystyrene, polymethyl groups and polydimethol groups. [0015] In U.S. Pat. No. 5,253,709, Kendrick, et al. offered a solution to the problem generated by irregularly shaped wellbore perforations, involving a hard centered ball with a deformable outer shell capable of deforming to the irregular shape of the casing perforation. The inner core was described to be made of binders and wax, while the outer covering was a rubber. According to the specification, the ball sealer would eventually come loose from the casing perforation after a period of time following release of the stimulation pressure. However, no mention as to the solubility or degradability, if any, of the balls was made. Further, ball specific gravities ranged from 1.0 to 1.3, but no pressure or temperature ratings were provided. [0016] Ball sealers comprised of a carbon-fiber reinforced polyetherketone polymer and having a density less than that of the treatment fluid were described by Gonzalez, et al. in U.S. Pat. No. 5,309,995. Such ball sealers are described as having a density in the range of 1.1 g/cc to 1.3 g/cc and suitable for use in downhole environments having a temperature in the range of 177-316.degree. C. and a pressure in the range of 350-1758 kg/cm.sup.2. [0017] U.S. Pat. No. 5,485,882 to Bailey, et al. suggests rigid, hollow-core, low-density (0.8-1.3 g/cc) ball sealers suitable for use in cased wells at temperatures up to 400 F, hydrostatic pressures up to 20,000 psi, and differential pressures across the perforations up to 1,500 psi. The ball sealers are comprised of two pieces made of a high strength material, such as aluminum, and an optional high-strength thermoplastic rubber cover. Deformable ball sealers comprised of oxyzolidine, collagen and water and having a specific gravity in the range of 0.5 to 2.0, as well as methods for their manufacture, have been described in U.S. Pat. Nos. 5,990,051 and 6,380,138 to Ischy, et al. [0018] In SPE 13085 ["The Design of Buoyant Ball Sealer Treatments", (1984)], Gabriel and Erbstoesser describe a methodology to maximize and optimize both the benefits which can be realized from and the composition of buoyant ball sealers having a density less than that of heavy treatment fluids but less than or equal to that of light treatment fluids. New water-soluble perforation ball sealers for use as diversion agents have been described in detail by Bilden, et al. [SPE Paper 49099, pp. 427-436 (1998)]. These water-soluble perforation ball sealers are composed primarily of injection-molded collagen, are stable in all hydrocarbon fluids, have a specific gravity from 1.11-1.25 g/cc, and are reported to be able to withstand perforation differential pressures from 500 to 3,000 psi. [0019] All of these more recent ball sealer designs have resulted from an effort to develop a lower density ball that could withstand high temperatures and pressures or would seal more effectively. However, these recent designs have inherent problems including manufacturing and/or ingredient costs and limitations, density control issues, and performance limits, particularly with respect to hostile well environments. [0020] Thus, there exists a need for an improved ball sealer having the ability to divert fluid flow from casing perforations of high permeability to perforations of low permeability, that is, capable of deformation to conform to the shapes of casing perforations, will retain its strength and form during a stimulation process, and that will degrade into products soluble in the fluids found in subterranean wellbores after the stimulation process is complete. SUMMARY OF THE INVENTION Continue reading about Degradable ball sealers and methods for use in well treatment... Full patent description for Degradable ball sealers and methods for use in well treatment Brief Patent Description - Full Patent Description - Patent Application Claims Click on the above for other options relating to this Degradable ball sealers and methods for use in well treatment patent application. ###  How KEYWORD MONITOR works... a FREE service from FreshPatents1. Sign up (takes 30 seconds). 2. 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